The Ku, Maloob and Zaap (KMZ) complex is located offshore in the shallow waters of the Gulf of Mexico, in the bay of Campeche, 105 kilometers from Ciudad del Carmen. The complex oil production averaged 850,000 BOPD in 2012. KMZ has been Mexico's largest contributor to production since January 2009. The fluid is heavy oil of 22°API in Ku, and 13°API in Maloob-Zaap. The Cretaceous is the main producing formation. This carbonate reservoir is a naturally fractured dolomite that also contains matrix and vuggy porosity. Average permeability and gross thickness are 4,000 md and 700 m, respectively.Field production began in 1981. More than 150 wells were active in 2012. The initial reservoir pressure of 4,594 psi declined to about 1,707 psi as of 2012. Nitrogen injection began in 2009 for pressure maintenance.Reservoir simulation has been used in the KMZ complex during the last 15 years to support key reservoir management decisions. The Cretaceous reservoir was simulated as a dual porosity/single permeability system. The different fluids of Ku and Maloob-Zaap were each represented by a 6-component equation of state. The simulation was implemented as compositional to model the nitrogen injection. The aquifer volume was represented by applying pore volume multipliers to grid cells. One set of gas-oil and water-oil relative permeability and capillary pressure was assigned to the whole reservoir, along with one pressure dependent pore volume compressibility. Simple input parameters were used whenever possible for the history match.The simulation model matched the historical pressure and the production of oil, water, and gas by field satisfactorily. The match by well was fit-for-purpose. The production/injection forecasts helped support reserves, the complex plateau rate, the pressure maintenance strategy, the development scenario, and the timing and capacity of future facilities needed to manage increasing water production. This case study shows that even though reservoir simulation has limitations as any other tool, it is excellent for validating reservoir mechanisms and serving as the basis for estimating field long-term production performance, and providing support for economic and financial decisions.

Bacab field is located offshore in the Bay of Campeche approximately 100 km north of Ciudad del Carmen, Campeche, Mexico. The main producing reservoir in the field is the BKS reservoir, a Cretaceous age naturally-fractured reservoir with aquifer support. Most producers were completed near the formation top to avoid water encroachment through channeling or coning, however several producers had early water breakthrough, which impacts well performance and shortens well life. Pressure transient tests and production data were analyzed to identify various flow regimes present in Bacab wells. It was done to explain the early water breakthrough, determine appropriate operating conditions to control water production in wells near faulted areas, and better design future field development strategy. Using static reservoir characterization and dynamic reservoir simulation, we iterated and validated these elements to match the history of the wells. Numerical simulation results and pressure transient analysis (PTA) from a BKS well completed around the fault indicated the fault is conductive, which explains that the well's rapid water production was caused by water channeling through the fault. On the other hand, PTA results from several other wells suggested a constant pressure boundary, validated by the fact that the reservoir pressure drop is insignificant throughout the entire production history (approximately 22 years). This confirmed the primary reservoir drive mechanism in BKS is a strong aquifer drive. The strong energy could be beneficial to oil production or could be risky in channeling water to producers. Therefore, it is crucial to characterize the aquifer and reservoir vertical connectivity to enhance the field development plan. Through integrated dynamic characterization, we successfully identified and validated several important reservoir features impacting well performance. These include reservoir dynamic properties in the vicinity of wells and faults, degree of reservoir connectivity, flow boundaries and the presence of a strong aquifer. With these inputs, we were able to successfully model the wells and reservoir and optimize BKS future exploitation designs. Furthermore, we established guidance of operating wells near conductive faults to maximize the oil recovery. An enhanced BKS field development plan based on this study is being implemented that includes well interventions and sidetracking. Accompanying reservoir management best practices in mitigating water coning and channeling while optimizing well production rates, preliminary results are promising.

This paper investigates the use of CO 2 as an EOR solvent for a heavy oil and high permeability naturally fractured reservoir complex in Mexico. The complex is under partial pressure maintenance by Nitrogen injection. First geological features and production performance are analyzed to discern peculiar pressure trends caused by natural depletion and N 2 injection in order to establish the nature of prevailing fluid communication and identify a confined site for CO 2 injection testing. An East Block in the North fields due to its unique dynamic faulting characteristics is found nearly compartmentalized to serve as a suitable site for CO 2 -EOR injection studies. Second, a finely-gridded dual permeability compositional simulation sector model with local grid refinement and boundary flux scheme is constructed and a calibrated 8-component EOS along with full tensor molecular diffusion is implemented to model CO 2 -EOR process mechanisms. CO 2 and N 2 injections into the gas cap at varying rates and huff-n-puff injection in the oil column are simulated. The impact of injection rate is illustrated, where injection of CO 2 at low rates promotes diffusion and is shown to drain more of the matrix oil. The huff-n-puff simulation cases also indicate increased oil recovery and reduced matrix oil saturation by CO 2 injection as compared with N 2 injection due to a combination of oil swelling, reduced oil viscosity and partial miscibility with CO 2 . The paper concludes that the efficiency of CO 2 injections is more pronounced at higher reservoir pressures and with no or less volumes of prior injected N 2 .